Industrial plants that consume large amounts of carbon fuels, such as power, cement and iron and steel plants, increasingly require flexibility in their operations associated with the volatility of the cost of fuels and the price of products, as well as the regulatory and market environment particularly associated with carbon emissions. In such cases there are benefits to be obtained from adopting a mix of fuels, such as fossil fuels of coal and natural gas, which attract emissions penalties, and biomass and waste which typically do not. There is a need for production processes that can interchange such fuels. Such a flexible fuel plant can operate in any of the regimes of (a) full carbon emissions from combustion of fossil fuels with no sequestration, with emissions penalties, (b) with negligible emissions from either combustion of fossil fuels with sequestration of carbon dioxide (CO2) or combustion of non-fossil fuels without sequestration, with no emissions penalties (c) negative carbon emissions from combustion of non-fossil fuels with sequestration of CO2, which may be a source of revenue with emissions trading schemes. The optimal operating conditions may change on the timescale of hours to days due to market variability in input and output prices, including those from carbon emissions. In addition, there may be an additional uncertainty in long term operating costs over the timescale of the lifetime of the industrial plant, potentially rendering the plant uneconomic, arising from changes to the regulatory environment for CO2 emissions. In this environment, there is a need for a flexible approach to carbon capture in which the plant can operate in any of these regimes.
With the high capital cost of industrial processing plants, the need for flexibility in the use of the plant is particularly important. For example, an operator may have a choice of using fuel inputs, such as coals of various grades, natural gas (NG), biomass or waste. The operator may also benefit from a choice of derived fuel products, including Hydrogen, Synthetic Natural Gas (SNG), and a choice of whether or not to process the carbon dioxide for sequestration. There is a need for a flexible process that can use a variety of fuel inputs to produce a variety of fuel outputs with and without carbon capture. More specific examples are considered below.
One approach to reduce CO2 emissions from the combustion of solid fuels such as coal, biomass and waste is pre-combustion carbon capture from Syngas produced by the partial oxidation of such solid fuels with steam and oxygen in a Partial Oxidising Gasifier. Syngas comprises the combustible gases hydrogen, carbon monoxide and smaller amounts of methane and other hydrocarbons. It also contains significant amounts of CO2 and steam. In this approach, further CO2 is generated by the Water-gas Shift reaction with steam, separated, compressed and sequestered, with the production of hydrogen as the fuel gas stream. This process is the basis of the Integrated Gasification Combined Cycle (IGCC) system for power generation. It is believed that this process, without CO2 capture, has about the maximum efficiency for power generation. While the Partial Oxidising Gasifier technology is versatile with respect to the solid fuel source, decarbonation using pre-combustion capture technologies, such as the Benfield separation process and the Water Gas Shift reaction, incurs a significant energy penalty, and the costs of CO2 capture are significant. In addition, hydrogen is difficult to transport and store, so that such a system must produce hydrogen on demand. Underground Coal Gasification produces Syngas directly from a coal stream.
In both cases, the gasification reaction occurs at high pressure, generally in excess of 20 bar, and the output temperature is controlled by quenching with water, but is optimally about 800-900 C, say 850 C before gas clean-up. In most commercial Partial Oxidising Gasifiers, pure oxygen is injected into the Gasifier. The compressed oxygen is extracted from the air in an Air Separation Unit. In other Partial Oxidising Gasifiers, compressed air is introduced directly into the gasifier, with the consequence that the Syngas also contains inert gases such as nitrogen and argon.
There is a need for a decarbonation technology that can decarbonise Syngas produced from any of these processes, to produce a decarbonised hydrogen fuel stream, with or without inert gases, and a separate carbon dioxide gas stream, with a low energy penalty.
Another gasifier approach is to hydrogasify the solid fuel with hydrogen, and often with steam, in a Hydrogasifier to produce a fuel gas which comprises combustible components methane, carbon monoxide and hydrogen, and smaller amounts of other hydrocarbons. This fuel gas stream, called herein Hydrogas, can be partially decarbonised to produce a hydrogen gas stream that is fed back into the Hydrogasifier, a methane rich gas stream, called Synthetic or Substitute Natural Gas (SNG), and a separate CO2 stream for sequestration. SNG production is only a partial decarbonisation process, typically with about 50% decarbonisation, because the SNG carries about 50% of the initial carbon and the CO2 the other amount. The decarbonation of Hydrogas removes carbon from CO and CO2 in the Hydrogas, but not from methane, to ensure that the SNG meets the high Calorific Value specifications of NG. This partial decarbonation of Hydrogas can be achieved using established pre-combustion capture technologies, such as the Benfield or amine processes in conjunction with steam and the Water-Gas Shift reaction. However, this process incurs a significant energy penalty, so that the costs of CO2 capture are significant. There is a need for a decarbonation technology that can partially decarbonise Hydrogas to produce a hydrogen stream, an SNG fuel stream, and a separate carbon dioxide gas stream, with a low energy penalty. Underground Coal Hydrogasification produces Hydrogas directly from a coal stream through the injection of hydrogen, with steam if required. This Hydrogas can be decarbonised as described above.
The reduction of emissions from the combustion of NG, and thus SNG, is required to further reduce the CO2 emissions. Generally, the carbon emissions from combustion of NG/SNG is about 50% less of the CO2 emitted from the combustion of a solid fuel per unit of thermal energy produced. Further reduction of CO2 emissions from combustion of NG/SNG can be achieved by post-combustion carbon capture, for example using amine technology. Pre-combustion decarbonisation of NG/SNG can be achieved by steam reforming the NG/SNG to produce Syngas, and the Syngas fuel stream is then decarbonised as described above for Syngas from a Partial Oxidising Gasifier. This gives a hydrogen gas stream for combustion and a separate carbon dioxide stream for sequestration. The separate processing steps of Steam Reforming, Water-Gas Shifting and CO2 capturing using, for example, the Benfield process, has a significant energy penalty. There is a need for a decarbonation technology that can decarbonise NG/SNG in a single reactor to produce a decarbonised hydrogen fuel stream and a separate carbon dioxide gas stream, with a low energy penalty.
For example, a power generator may have access to solid fuel from a nearby coal, biomass or waste resources to produce Syngas from a Partial Oxidising Gasifier, and also have access to NG from a gas pipeline or from coal stream extraction. In this case, it may be desirable to have the flexibility to decarbonise either the Syngas or the NG to give a continuous hydrogen gas stream for power generation.
In another example, the power generator has chosen to produce SNG from Hydrogas and may benefit from diverting excess production of SNG into the NG pipeline, if only to access the gas storage capabilities of typical gas distribution systems. This would allow the operation of the Hydrogasifier at its maximum capacity even if the demand for power is low. In this approach, it would be preferable for a single stage process in which the decarbonation process can be switched from production of hydrogen to production of SNG, or a separable mixture thereof. Such a system would desirably be controlled to meet the variable demand for power taking into account the market for SNG and CO2.
A need therefore exists to provide a system and method for processing an input fuel gas of variable composition, such as Syngas, Hydrogas, NG, SNG or mixtures thereof with steam to produce an output fuel gas with a controlled composition and a separate CO2 gas stream that seek to address at least one of the above mentioned problems.